Method for designing corrosion resistant alloy tubular strings

ABSTRACT

A method to design an oilfield tubular string for a well includes determining the corrosiveness of fluids in the well and selecting an alloy for the oilfield tubular string, such that a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process, heat treating the alloy to survive the determined well fluid corrosiveness and determining the yield strength of the heat treated alloy, and selecting a diameter, a wall thickness, and a connection type for the oilfield tubing string based on the determined yield strength.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates generally to a method for designing tubular strings. More particularly, the invention relates to a method of designing corrosion resistant alloy tubular strings.

2. Background Art

In recent years, oil and natural gas wells which could be easily drilled have been exhaustively drilled, and wells in severe drilling environments, such as severely corrosive environments, deep wells, cold environments, and sea bottoms, are more commonly drilled. As a result, many oil and gas reservoirs are being explored under corrosive environments in the presence of corrosive fluids including oxygen (O₂), hydrogen sulfide (H₂S), and carbon dioxide (CO₂) gasses. Therefore, many downhole components are exposed to a variety of corrosion mechanisms including, but not limited to, uniform corrosion, pitting, corrosion fatigue, sulfide stress cracking, hydrogen blistering, hydrogen embrittlement, stepwise cracking, wormhole attack, galvanic ringworm corrosion, heat affected corrosion, mesa attack, raindrop corrosion, and erosion corrosion.

For example, a significant problem presented by the presence of H₂S is metal embrittlement or sulfide stress cracking (SSC), caused by penetration of H₂ and/or H⁺ into the metal crystal lattice of the steel. When H⁺ has migrated or diffused into the steel, it may recombine to form H₂, which occupies significantly more volume than hydrogen ions causing significant stress on the metal crystal lattice. Thus, because hydrogen sulfide is a weak acid when dissolved in water, it can act as a catalyst in the absorption of atomic hydrogen in steel to promote sulfide stress cracking in high strength steels. Sulfide stress cracking typically occurs when H₂S corrosion is accelerated by stresses. Hydrogen embrittlement fractures are caused by the migration of hydrogen into the metal and internal concentration of the hydrogen in high-stress areas, making the metal very brittle. Hydrogen-induced cracking may also occur if the metal is subjected to cyclic stresses or tensile stress. Herein, SSC refers to hydrogen-induced cracking, i.e., cracking induced by entry of hydrogen generated by a cathodic reaction into steel, and is distinguished from stress corrosion cracking (SCC) accompanied by an anodic reaction and a solution of electrode.

To mitigate their negative impacts on field operation, it is known in the art to try to control this tubular corrosion by making the tubular joints from corrosion-resistant alloy (“CRA”), such as stainless steels or nickel-based alloys, by adding corrosion-inhibiting chemicals to the fluid stream, or by lining the exposed inner surfaces of the tubular joints with a corrosion-resistant lining or coating. However, the use of inhibitors increases cost and may result in insufficient protection at high temperatures, and leakage thereof causes environmental contamination. Thus, CRAs not requiring inhibitors have been more commonly used in recent years. As used herein, CRAs are defined as those alloys whose mass-loss corrosion rate in produced fluids is at least an order of magnitude less than carbon steel.

The material selection of tubular string for sour wells is thus of increasingly greater importance. In Oil Country Tubular Goods (OCTG), martensitic stainless steel containing 13% chromium is widely used as a CRA. However, in choosing a material, it is often necessary to balance corrosion resistance, cost-effectiveness, reliability, and strength. With increasing well depths, there exists a greater need for higher corrosion resistance and increased strength of the tubular material. Similarly, greater corrosion resistance is of greater importance as temperature, pressure, acidity, and concentrations of CO₂, chloride, and H₂S increase. Because each of these conditions is dependent upon the characteristics of the formation and the drilling environment, including drilling fluids, every well may have different material requirements to withstand corrosion.

In general, resistance to stress corrosion cracking (SCC) and/or hydrogen embrittlement (sulfide stress cracking or SSC) increases with increasing alloy nickel, chromium, molybdenum, tungsten, and niobium content. These materials may be cold-worked or age-hardened in order to obtain the strength needed to support the weight of several thousand meters of tubing and withstand high pressures.

While several alloys have established corrosion resistance attributes for use in drilling applications, they are extremely costly when used as a solid wall tubular. The exorbitant cost of solid wall CRA tubulars has resulted in many projects being deemed uneconomical or postponed. Accordingly, there exists a need for a method of selecting a downhole tubular that minimizes corrosion of the tubular and is economically efficient.

SUMMARY OF INVENTION

In one aspect, the present invention relates to a method to design an oilfield tubular string for a well. Preferably, the method includes determining the corrosiveness of fluids in the well and selecting an alloy for the oilfield tubular string, such that a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process. Furthermore, the method preferably includes heat treating the alloy to survive the determined well fluid corrosiveness and determining the yield strength of the heat treated alloy. Furthermore, the method preferably includes selecting a diameter, a wall thickness, and a connection type for the oilfield tubing string based on the determined yield strength.

In another aspect, the present invention relates to a method to design an oilfield tubular string for a well. Preferably, the method includes determining a corrosiveness of fluids in the well, specifying a maximum outer diameter of the oilfield tubular string, and selecting a alloy for the oilfield tubular string, such that a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process. Furthermore, the method preferably includes heat treating the alloy to survive the determined well fluid corrosiveness and determining the yield strength for the heat-treated alloy. Furthermore, the method preferably includes selecting a wall thickness for the oilfield tubular string based upon the determined yield strength.

In another aspect, the present invention includes a method to design an oilfield tubular string for a well. Preferably, the method includes determining a corrosiveness of fluids in the well and selecting an alloy for the oilfield tubular string, such that a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process. Furthermore, the method preferably includes performing a heat treatment on the selected alloy, wherein the heat treatment enables the alloy to exhibit a desired yield strength. Furthermore, the method preferably includes determining the corrosion resistance of the heat treated alloy and buffering the fluids in the well such that the corrosion resistance of the heat treated alloy is sufficient to survive the corrosiveness of the buffered fluids in the well.

In another aspect, the present invention includes a method to design an oilfield tubular string for a well. Preferably, the method includes determining the corrosiveness of fluids in the well and selecting an alloy for the oilfield tubular string, such that a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process. Furthermore, the method preferably includes determining the yield strength of selected alloy at the determined corrosiveness and heat treating the alloy to obtain the determined yield strength. Furthermore, the method preferably includes selecting a diameter, a wall thickness, and a connection type for the oilfield tubing string based on the determined yield strength.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

DETAILED DESCRIPTION

In one aspect, selected embodiments of the invention relate to a method for designing a corrosion resistant alloy (CRA) tubular string based on determined downhole conditions. These determined conditions may be either directly or indirectly measured, or estimated with models or historical data. As such, the geometry of a tubular string may be specified as a result of the yield strength of a selected CRA. As wells are drilled to increasing depths, gas compositions encountered in the formation require tubulars that possess corrosion resistance. For example, if hydrogen sulfide and/or carbon dioxide gases are dissolved in an aqueous solution and are able to react with the tubular string, failure of the tubular string is more likely to result as compared to the particular tubular string used at a similar depth, pressure, temperature, etc. without the presence of the corrosive gases. Thus, because of the presence of certain downhole conditions, such as high acidity and/or elevated levels of H₂S, CO₂, and chloride ions, pipes selected for use in a well should exhibit sufficient corrosion resistance and yield strength to prevent downhole failure.

Examples of corrosion and/or erosion resistant CRA-type materials include: (1) stainless steel including conventional austenitic, martensitic, precipitation hardened, duplex, and ferric stainless steels; (2) precipitation hardened and solid solution nickel-based alloys and nickel copper alloys; and (3) cobalt-based, titanium, and zirconium alloys. This description of the general classification of corrosion and/or erosion resistant CRA materials includes a myriad of material options, depending upon the application under consideration, and is merely intended to be illustrative of suitable materials for use in practicing the present invention. In one embodiment, the selected CRA may be a martensitic CRA. As such, examples of martensitic CRA materials in accordance with embodiments of the present disclosure include, but are not limited to, 13Cr steel and A-21 steel (described in U.S. Pat. No. 5,310,431, issued to Robert F. Buck on May 10, 1994 and hereby incorporated herein by reference in its entirety). Furthermore, while “acidity” is referred to as a particular form of corrosiveness affecting CRA materials, it should be understood that other mechanisms of corrosion and corrosion resistance may be used in conjunction with the method disclosed herein and are not outside the scope of the disclosed invention.

Typically, the corrosion resistance of a CRA tubular at a given yield strength varies inversely with respect to the acidity of the drilling environment. That is, as the yield strength of a CRA is increased, it more susceptible to corrosion resistance by acid. The acidity of the drilling environment may be determined and/or predicted from, for example, simulations based on the geological formation and expected levels of H₂S, CO₂, and bicarbonate; offset well data; prior experience; and the drilling fluids and various additives to be used in a particular well.

Thus, depending on the acidity of the well fluid, and thus the amount of corrosion resistance required for a particular drilling application, a CRA may be selected so that the corrosion resistance may be optimized to obtain maximum yield strength allowable for a particular drilling environment. The desired yield strength necessary for the tubular pipe may also partially depend on the particular well in which it may be used, specifically with respect to expected temperatures, pressures, gas concentrations, and drilled depths, etc.

Depending on the expected downhole conditions, and thus potential modes of failure, one of ordinary skill would recognize that, depending on the type of corrosion to be prevented, different material selections may be made. For example, NACE MR0175 gives recommendations based on the properties, heat treatments, and environmental limits for the selection of the various alloys and/or classes of alloys that may be used to prevent SSC. The double-cantilever-beam method of NACE TM0177-96(D) (“NACE ‘D’”) may be used, for example, to evaluate the hydrogen SSC resistance of a tubular string at a particular pH by determining a critical stress intensity factor for a test specimen exposed to hydrogen sulfide bubbled through a solution of sodium chloride, glacial acetic acid, and sodium acetate. For a given pH, it can be experimentally determined whether a batch of a CRA material at a particular yield strength will pass the NACE “D” exposure test. Particularly, the NACE “D” test may offer a measure of the survivability of the material tested in a particular corrosive environment. In the case of oilfield goods, long-term emplacement in a corrosive downhole environment is common. Therefore, the results of the NACE “D” (or any other corrosiveness test available to one of ordinary skill in the art) may be useful in determining whether a particular alloy is an appropriate choice for a particular downhole condition.

Desired properties of a tubular good, such as yield strength and hardness, may be obtained by varying the heat treatments applied to the material in forming the tubular good. Specifically, by subjecting the alloys to a sequence of temperature changes, the temperatures of exposure, time of retention at specific temperatures, and rate of cooling may be used to achieve the desired material properties of the tubulars. Specific heat treatments include, for example, age hardening, quenching, solution heat treatment, and annealing, etc. In designing a CRA tubular, because the expense of the actual alloy material is so high, the costs associated with heat treating the material are slight in comparison. Thus, varying the heat treatments to produce specific yield strengths has little effect on the economic efficiency of the tubular string system.

Typically, OCTG, including CRA tubular strings, are manufactured according to minimum yield strengths in API “grades” or in strength “increments” for non-API standardized grades. For example, API grade L-80 would have a minimum yield strength of 80,000 psi, and API grade P-110 would have a minimum yield strength of 110,000 psi. Because OCTG are generally available at the specific gradations and are not tailored to a specific need in a particular well, a designer will typically select an CRA grade having a yield strength greater than the minimum yield strength necessary for an OCTG in a particular well to be drilled. However, because the various grading schemes for material properties often specify minimum values for yield strength, it is often the case that for a particular OCTG need, a selected grade will have a yield strength in excess of what is necessary.

For example, an L-80 steel may be delivered with an actual yield strength of 92,000 psi or greater. As such, if a tubing string having a yield strength of 90,000 psi is desired, a designer must select P-110 material over L-80 material as there is no guarantee that every batch of L-80 material will exceed the 90,000 yield. Thus, the spacing of grades, and the variability of the yield strengths within the grades, may result in wasted corrosion resistance for a particular alloy. Therefore, in many CRA applications, if a particular yield strength is needed for a tubular design, any excess in yield over that amount may represent an unnecessary reduction in the corrosion resistance of the pipe.

Upon selecting the CRA, the dimensions of the tubular string may be selected based on its corresponding yield strength. In particular, the requisite dimensions (diameter, wall thickness, connection type, etc.) of the tubular string for the particular well to be drilled may be determined by considering the yield strength necessary to withstand corrosion and the graded yield strengths available for the selected CRA from a manufacturer. As used herein, the difference between the graded yield strength and the yield strength necessary to withstand corrosion may be referred to as the yield strength differential. In one embodiment, the dimensions of the tubular string, including, for example, the diameter of the pipe and thickness of the pipe wall, may be optimized by considering the yield strength differential. The optimal pipe dimensions may be determined, for example, by using Barlow's formula, shown in Eq. (1) $\begin{matrix} {P = \frac{2{S \cdot T}}{\left( {{OD} - {2T}} \right) \cdot {SF}}} & (1) \end{matrix}$ where P is the internal pressure; T is the wall thickness; OD is the outside diameter; SF is the safety factor; and S is the material strength. In optimizing the dimensions of a tubular string, a designer may often consider the expense of the CRA to minimize the amount of material necessary for a particular tubular string without posing harm to the integrity of the system. In one embodiment, a designer may select a diameter of the tubular based on the yield strength of the selected CRA. In another embodiment, a designer may select a thickness of the tubular wall based on the yield strength of the selected CRA.

The yield strength may also be used to select an appropriate threaded connection. Generally, threaded connections for tubular strings are available in a wide range of “efficiencies.” The efficiency of a threaded connection may be expressed, for example, as tensile yield stress as a percentage of the pipe body yield stress. For a certain class of threaded connections, one type of thread may have a tensile efficiency of 50%, i.e., that the yield of the threaded connection is equal to 50% of the tensile yield of the pipe body itself. Typically, as the efficiency increases, the threaded connection becomes more expensive. In one embodiment, the differential yield strength may be used to select a threaded connection having a lower efficiency.

For example, if an operator requires an 18,000 foot string of casing with an outer diameter less than 5-¾ inches for a well having fluids at 3.8 pH, there are several CRA options available. A first option would be to use a 5″ string of 15 pound (i.e., 15 pounds per foot of length) of standard 13Cr martensitic CRA having a minimum yield of 80,000 psi having a threaded and coupled (T&C) connection rated at 100% efficiency. As such, this material is rated down to 3.5 pH by the NACE “D” test and the outer diameters of the couplings would be between 5.600 and 5.750 inches. Therefore, an 18,000 foot long string would weigh approximately 270,000 pounds (in air) and would have a cross-sectional area of 4.374 in², equating to a tensile yield load of 350,000 pounds.

Alternatively, a 5-½ inch string of 15.5 pound casing of high-strength martensitic alloy with an integral external-flush (i.e., a premium) connection with a 60.5% tensile efficiency and an outer diameter of 5.5 inches may be used. As such, at the specified acidity of 3.8 pH, the material could exhibit a yield strength of 110,000 psi. Therefore, an 18,000 foot long string would weigh approximately the same (279,000 lbs.) as the first option and with a cross-sectional area of 4.514 in², the pipe body tensile strength would be approximately 500,000 lbs. However, with a connection efficiency of 60.5%, the tensile yield for the entire string would be approximately 300,400 lbs.

Importantly, the inner diameter of the 5″ T&C would be about 4.408 inches and would result in an internal cross-sectional area of 15.26 in², while the 5-½ premium string would have a 4.950 inch inner diameter and a 19.24 in cross-sectional area, an increase in over 26%. The increased inner diameter and cross-sectional area allows increased production flow rates and may result in long-term cost savings to the operator. Furthermore, as CRA is typically sold by the pound, the material cost between the two strings would be roughly the same. However, as the second string employs more expensive premium connections, the labor and machine costs of the second string would be elevated. Nonetheless, it is expected that the increased flow rates enabled by the larger inner diameter would offset, if not exceed, these costs over time.

Furthermore, in another embodiment, a designer may look to the plausibility in altering the corrosivity of the well fluid when selecting a CRA and tubular string. The acidity of a well fluid may be controlled and/or altered by injecting buffering chemicals into the well fluid. Any buffering means as known in the art may be selected to buffer the well fluid to a target acidity. Thus, if a CRA having a particular yield strength is initially selected, a target acidity of the well fluid may be subsequently selected so that the CRA is adequately protected against corrosion.

In one embodiment, for a well fluid having a particular acidity level, the well fluid may be selectively buffered to a higher pH so that a higher yield strength and a tubular having thinner walls and/or altered diameters may be selected, effectively reducing the amount of CRA needed for the tubular. In another embodiment, the well fluid may be selectively buffered to a higher pH so that a higher yield strength may be selected and a less efficient threaded connection may be used.

Advantageously, the present invention provides for a method of selecting CRA tubulars for use downhole. The selection process may allow for a designer to balance economic efficiency of downhole tubulars with the corrosion resistance of the tubular string. Cost/benefit analysis may be performed in selecting CRA materials and/or the tubular string for a particular application. Safety factors may also be considered in determining, for example, appropriate dimensions and/or threaded connections for the tubular string. Former methods of designing corrosion resistant strings are significantly less efficient, in that the yield of materials manufactured to an API grade often exceed the minimum yield. Therefore, if an operator requests a particular API grade, the delivered steel may have an actual yield 10-15% greater than necessary. As such, the operator would verify the NACE “D” corrosion resistance and then produce the tubing therefrom. However, this former method would result in a tubing string that is heavier and weaker (for a given well corrosiveness) than is necessary.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. 

1. A method to design an oilfield tubular string for a well, the method comprising: determining the corrosiveness of fluids in the well; selecting an alloy for the oilfield tubular string, wherein a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process; heat treating the alloy to survive the determined well fluid corrosiveness; determining the yield strength of the heat treated alloy; and selecting a diameter, a wall thickness, and a connection type for the oilfield tubing string based on the determined yield strength.
 2. The method of claim 1, wherein the determined corrosiveness includes an acidity of the fluids in the well.
 3. The method of claim 1, further comprising maximizing the flow of well fluids through the oilfield tubular string with the selected diameter, wall thickness, and connection type.
 4. The method of claim 1, further comprising minimizing the oilfield tubular string weight with the selected diameter, wall thickness, and connection type.
 5. The method of claim 1, further comprising testing the survivability of the alloy at the determined corrosiveness of fluids in the well using a NACE “D” test.
 6. The method of claim 1, further comprising measuring the yield strength of the heat treated alloy with a hardness test.
 7. The method of claim 1, wherein the connection type is selected from the group consisting of non-upset, API upset, IEUE upset, threaded and coupled, and premium threaded connections.
 8. The method of claim 1, wherein the selected alloy comprises a corrosion resistant alloy.
 9. The method of claim 8, wherein the corrosion resistant alloy comprises martensitic stainless steel alloy selected from the group consisting of A-21 steel and 13Cr steel.
 10. A method to design an oilfield tubular string for a well, the method comprising: determining a corrosiveness of fluids in the well; specifying a maximum outer diameter of the oilfield tubular string; selecting a alloy for the oilfield tubular string, wherein a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process; heat treating the alloy to survive the determined well fluid corrosiveness; determining the yield strength for the heat-treated alloy; and selecting a wall thickness for the oilfield tubular string based upon the determined yield strength.
 11. The method of claim 10, wherein the determined corrosiveness includes an acidity of the fluids in the well.
 12. The method of claim 10, further comprising testing the survivability of the alloy at the determined corrosiveness using a NACE “D” test.
 13. The method of claim 10, further comprising minimizing the oilfield tubular string weight with the selected wall thickness.
 14. The method of claim 10, wherein the selected alloy comprises a corrosion resistant alloy.
 15. The method of claim 14, wherein the corrosion resistant alloy comprises martensitic stainless steel alloy selected from the group consisting of A-21 steel and 13Cr steel.
 16. A method to design an oilfield tubular string for a well, the method comprising: determining a corrosiveness of fluids in the well; selecting an alloy for the oilfield tubular string, wherein a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process; performing a heat treatment on the selected alloy, wherein the heat treatment enables the alloy to exhibit a desired yield strength; determining the corrosion resistance of the heat treated alloy; buffering the fluids in the well such that the corrosion resistance of the heat treated alloy is sufficient to survive the corrosiveness of the buffered fluids in the well.
 17. The method of claim 16, wherein the determined corrosiveness includes an acidity of the fluids in the well.
 18. The method of claim 16, further comprising testing the corrosion resistance of the alloy at the determined corrosiveness using a NACE “D” test.
 19. The method of claim 16, wherein the selected alloy comprises a corrosion resistant alloy.
 20. The method of claim 19, wherein the corrosion resistant alloy comprises martensitic stainless steel alloy selected from the group consisting of A-21 steel and 13Cr steel.
 21. A method to design an oilfield tubular string for a well, the method comprising: determining the corrosiveness of fluids in the well; selecting an alloy for the oilfield tubular string, wherein a corrosion resistance and a yield strength of the alloy may be varied through a heat treatment process; determining the yield strength of selected alloy at the determined corrosiveness; heat treating the alloy to obtain the determined yield strength; and selecting a diameter, a wall thickness, and a connection type for the oilfield tubing string based on the determined yield strength.
 22. The method of claim 21, further comprising maximizing the flow of well fluids through the oilfield tubular string with the selected diameter, wall thickness, and connection type.
 23. The method of claim 21, further comprising minimizing the oilfield tubular string weight with the selected diameter, wall thickness, and connection type. 